CEC Approves EV Fast Chargers Along Calif. Highway Corridors

The California Energy Commission granted about $15 million to companies to install more than 100 electric vehicle fast charger stations in the Golden State.

The CEC on Dec. 8 voted to approve about $11.2 million for San Francisco-based Electric Era to install 72 direct current faster chargers (DCFCs) at 16 locations along some of the state’s major highways, including Interstate 80, from Auburn to Grass Valley, and U.S. 101, from San Francisco to Los Angeles.

The source of the grants is the $5 billion Biden-era National Electric Vehicle Infrastructure (NEVI) program, which was funded by the federal Infrastructure Investment and Jobs Act. The Trump administration halted NEVI payments early in 2025 but resumed the program in August after a court ruling. (See DOT Issues Guidance to Resume NEVI Funding.)

Under the terms of the grants, the Federal Highway Administration (FHWA) must authorize funding for the projects before reimbursable expenditures can be incurred, the CEC’s application says. Even where funds have already been obligated or work to be performed will not be reimbursable or will be done with matching funds, FHWA and California Department of Transportation (Caltrans) approval may still be required prior to commencing work, the application says.

Rivian, an EV truck manufacturer, received four grant awards, totaling about $1.7 million, to install DCFCs in Long Beach, Temecula, Tulare and Cabazon. As part of the grant, Rivian must sign a data-sharing agreement with a charging network provider, which will collect and send to the CEC charging data from each charging port, the application says.

The CEC approved also the commission’s 2025-2026 investment plan update for the clean transportation program, which included a significant drop in funding for EV light-duty chargers, from $98.5 million in 2025/26 to $34.2 million in 2026/27. EV heavy-duty vehicle charger funding will increase from $15 million in 2025/26 to $44 million in 2026/27.

In total, the transportation investment plan includes about $327 million for fiscals 2025/26 through 2027/28.

“[We are] targeting the expansion of charging in multifamily housing properties,” Commissioner Nancy Skinner said at the agency’s voting meeting. “Because in the analysis we’ve done, multifamily residents have the least access to charging at home. And so, since charging at home is one of the most convenient ways to have an EV, we really want to expand multifamily charging installations so that it is much more convenient for folks.”

POU IRPs Approved

The CEC also approved the integrated resource plans (IRPs) for the City of Palo Alto Utilities and Hetch Hetchy Power (HHP).

The approved IRP requires a publicly owned utility (POU) to meet greenhouse gas emission reduction requirements, renewable energy resource procurement amounts, and carbon neutrality and reliability requirements, the CEC’s Palo Alto order notes.

Palo Alto’s IRP shows that the utility will increase its investments in geothermal power generation, renew a hydroelectric generation contract with the Western Area Power Administration, and see an increased reliability risk during years with low hydroelectric generation availability.

Most of Palo Alto’s capacity — about 230 MW out of 340 MW — is provided by hydroelectric generation facilities, and about 80 MW from solar power generators.

HHP, which is operated by the San Francisco Public Utilities Commission (SFPUC), has 380 MW of existing resources. The utility anticipates low growth over the coming years, mostly driven by the San Francisco International Airport expansion, public transit electrification and new developments, CEC staff member Bryan Neff said at the meeting.

HHP transmits power across 167 miles of transmission infrastructure that is owned and operated by SFPUC, Neff said.

HHP’s load growth will require additional resources by 2033, so the utility plans to procure 75 MW of battery storage capacity starting in 2027, 100 MW of solar generation starting in 2033 and 50 MW of geothermal starting in 2035, the CEC’s staff review says.

“I think we’re seeing this in all the IRPs from the POUs: There is significant load growth in the upcoming years,” CEC Vice Chair Siva Gunda said at the meeting. “I think that’s consistent with the demand forecast of the CEC.

“When we think about California as a whole, we generally think about CPUC as a significant part of the work, and about 75 to 80% of the load does fall under the CPUC jurisdiction. But there’s almost a quarter, depending on the time of the year, that is planned through the POU work. … There’s also a lot of transmission work that is being taken up by the POUs, and [this is] something that we need to closely track.”

There is significant uncertainty in the load in the West and significant uncertainty in what resources are online, Gunda said.

“It’s important for us to track through our dependence on imports and just really be careful of planning that.”

Analysis: OSW and Gas Together Help NYISO, ISO-NE Grid Reliability

Northeastern power systems cannot afford to drop offshore wind if they are to maintain reliability, reduce emissions and lower electricity prices, according to a new analysis from Charles River Associates.

The analysis, released Dec. 2, examined both NYISO and ISO-NE and found that retaining existing natural gas while completing queued OSW projects were necessary to maintain reliability and affordability.

“We found that there are quite material resource adequacy risks in New York City,” Oliver Stover, an associate principal of Charles River, said during a webinar Dec. 4 to discuss the paper. “This is important from the perspective of offshore wind because it can have a non-trivial impact on helping reduce these risks.”

Stover went on to say that New England’s exposure to tightening natural gas and electricity markets could be mitigated by investment in OSW.

The base case in the analysis assumes that the current queue of OSW projects in both markets will be completed on time and that existing gas resources are retained. When compared to cases in which OSW is canceled without substitutes, replaced by onshore renewables or replaced by gas, the base case performed better on prices and reliability.

Developing gas alone was found to raise prices and emissions while possibly reducing overall capital costs. Onshore renewables could match base case prices and emissions but were weaker for reliability without extensive transmission upgrades. Failing to bring on new resources at all had the worst overall performance.

“This is not just a winter problem, particularly in the New York ISO,” Stover said. “We see summer challenges continuing into the nighttime hours, and offshore wind is well positioned to augment solar builds in filling in those hours.”

These findings mirror the policy preferences of major stakeholders and politicians in New York. The Independent Power Producers of New York, the Alliance for Clean Energy New York and Gov. Kathy Hochul have previously stated that they favor an “all of the above” approach to energy.

Stover said that OSW’s proximity to load pockets, particularly in New York City, made it better for reliability than onshore renewables in general. Bypassing transmission congestion to inject directly into load pockets was a major source of OSW’s reliability benefits in the analysis. Without OSW development, both Boston and Vermont were at risk of load shedding by 2036.

Gas-fired generation development is difficult in high-population areas of both New York and New England. The existing gas system is already constrained, and there is limited headroom on the gas distribution system to bring on more firm generation, Stover said.

“They are both challenging places to build. They’re expensive. They’re coastal. They’re quite dense, and there is limited fuel,” Stover said. “Those problems might be solved in the long term … but that might be challenging.”

Stover also pointed to a recurring topic of conversation at NYISO stakeholder meetings: the aging fossil fleet. If nothing new comes online, it places greater burdens on aging infrastructure, which increases the likelihood of generator failure and forced retirement. ISO-NE’s generation portfolio is a little more flexible in this respect, as the region could afford to retire units more than New York.

While reliability and energy prices fell in the base case “OSW+ NG” scenario, capital costs were slightly higher than the gas-only scenario. Stover said that this was because OSW, and renewables broadly, required more infrastructure investment to bring them online.

“You have to pay for the upfront capital cost, and then we enjoy the benefits of paid dividends on driving down the energy price,” Stover said.

Federal Briefs

BOEM to Consider Revoking New England Wind 1 Approval

The Bureau of Ocean Energy Management last week filed a request with a federal judge asking to allow it to reconsider a key approval for New England Wind 1 project planned off the Massachusetts coast. 

The filing comes more than two months after the government signaled it would take such action against the project.

It is at least the third time the administration has sought a remand of an offshore wind project approval, the others being for SouthCoast Wind and US Wind. The permits give major infrastructure projects the certainty to secure financing and move forward with construction.

More: The New Bedford Light

TVA Wins $400M Grant for Next-gen SMR

The Department of Energy last week awarded the Tennessee Valley Authority a $400 million grant for the development of the GE Hitachi BWRX-300 reactor.

Gen III+ reactors are advanced light water reactors that incorporate newer safety features and higher performance capabilities.

The grant was established by Congress in 2024.

More: Knoxville News Sentinel

Trump Admin Renames National Renewable Energy Lab

In a press release published Dec. 1, the Department of Energy has renamed the National Renewable Energy Laboratory the National Laboratory of the Rockies, effective immediately.

DOE said the renaming “reflects the department’s renewed focus on ‘energy addition,’ rather than the prioritization of specific energy resources.”

The laboratory was created in 1977 as a response to the 1973 energy crisis and has focused on the development and commercialization of a wide range of technologies, including photovoltaic cells, energy-efficient windows and hydrogen fuel cells.

More: CPR News; Inside Climate News; National Laboratory of the Rockies

Company Briefs

Amazon Backs out of Project Blue Data Centers

Amazon Web Services has pulled out of its role as future operator of the Project Blue data center complex in the Tucson, Ariz., area, according to sources.

Amazon has left the project because its operations aren’t compatible with the project’s recently announced plans to use air cooling instead of water cooling for the data centers’ servers, the sources said. Beale Infrastructure, the project’s developer, is now negotiating with Meta to replace Amazon as the center’s operator.

Project Blue switched to plans for an air-cooled operation after the Tucson City Council voted unanimously to kill its effort to be annexed into the city and to receive city water supplies for its operations.

More: Tucson.com

Exxon Halts Plans for Low-carbon Hydrogen Facility

ExxonMobil has pulled the plug on what would have been one of the world’s largest hydrogen plants after its $332 million grant from the Biden administration was taken away by the Trump administration.

In 2022, Exxon announced plans to build a facility at its refining and petrochemical complex in Baytown, Texas, with the capacity to produce 1 Bcfd of blue hydrogen, which is made using natural gas and carbon-capture equipment.

Since blue hydrogen typically costs about one-third more than the ​“gray” version of the fuel made with unmitigated gas, Exxon CEO Darren Woods said the company could not find enough buyers willing to pay the premium.

More: Canary Media

Eurowind Energy Exits 400-MW Battery Project

Danish renewables developer Eurowind Energy last week announced the sale of a 400-MW battery storage project in California under a plan that will provide it with cash for its European activities.

The divestment is in the Potentia-Viridi battery energy storage system project, which Eurowind Energy developed under a 50/50 joint venture with Capstone Infrastructure.

The project is expected to come online in June 2028.

More: Renewables Now

State Briefs

ALABAMA

Alabama Power Moves Ahead with 2-year Rate Freeze

Alabama Power last week announced that all components of the company’s regulated retail rates are not scheduled to increase through 2027.

Alabama Power said it will hold in place all existing factors in customer rates, including delaying until 2028 the implementation of previously approved adjustments for the Lindsay Hill generation facility.

The move comes a year after the company projected a nearly 2% rate reduction for 2025.

More: Alabama.com

COLORADO

PUC Mandates Emissions Cuts for Gas Utilities

The Public Utilities Commission voted 2-1 for investor-owned gas utilities to cut carbon pollution by 41% from 2015 levels by 2035.

The target — which builds on goals already set for 2025 and 2030 — is more consistent with the state’s aim to decarbonize by 2050 than the other proposals considered. Commissioners rejected the 22 to 30% cut utilities asked for and the 31% target state agencies recommended.

If utilities hit the 2035 mandate, they will avoid an estimated 45.5 million metric tons of greenhouse gases over the next decade, according to the state’s Energy Office and the Department of Public Health and Environment.

More: Canary Media

IOWA

UC Approves Tx Lines to Power Data Centers

The Utilities Commission last week approved a $221 million high-voltage transmission line project that will help power two large data center developments under construction in Cedar Rapids.

The order will allow ITC Midwest to build a 61-mile, 345-kV transmission line and rebuild another 34-mile, 161-kV transmission line. The project is key to providing power to two new, large energy users in Cedar Rapids’ Big Cedar Industrial Park.

More: Des Moines Register

NORTH DAKOTA

Judge Finds Carbon Dioxide Storage Law Unconstitutional

Northeast Judicial District Judge Anthony Swain Benson last week sided with a landowner group and found a state law related to underground storage of carbon dioxide to be unconstitutional.

The Northwest Landowners Association sued North Dakota and the Industrial Commission in 2023, challenging a law that requires landowners to allow carbon dioxide storage beneath their property if at least 60% of the affected landowners agree to the project. 

Benson wrote in his order that the state law is unconstitutional because it allows a government-authorized taking of property without an avenue for “just” compensation determined by a jury. In this case, the property is pore space — cavities in underground rock formations where emissions can be trapped.

More: North Dakota Monitor

PENNSYLVANIA

PUC Slashes Columbia Gas Rate Hike

The Public Utility Commission last week reduced a Columbia Gas rate increase.

Columbia Gas looked to raise the residential customer charge from $17.25 to $31.97/month. The PUC approved a charge of $23/month.

The new rates will take effect on or after Jan. 1.

More: WHTM

UTAH

Rocky Mountain Power Requests Rate Increase to Feed Fire Fund

Rocky Mountain Power last week filed a request with the Public Service Commission seeking a 4.48% rate increase for all customers.

The company’s request stems from a law the state passed in 2024, which allowed utilities to establish a restricted fire fund fed by a surcharge to ratepayers. With the increase, the company is hoping to collect about $109 million a year, and eventually, after 10 years, about $1 billion.

The increase would translate to about $3.70/month for the average residential customer.

More: Utah News Dispatch

WASHINGTON

Gov. Ferguson Approves Large-scale Solar Farm

Gov. Bob Ferguson last week notified the Energy Facility Site Evaluation Council that he approved the 1,300-acre Carriger Solar project.

The 160-MW project will also have 63 MW of battery storage and will tie into the Bonneville Power Administration transmission system.

More: Washington State Standard

WISCONSIN

PSC Approves Utilities’ Renewables Purchases

The Public Service Commission approved three utilities’ plans to purchase four new renewable energy projects.

The purchases include the Saratoga Solar Energy Center, the Ursa Solar Park, the Badger Hollow Wind Farm and the Whitetail Wind Farm. The projects all had previous approvals from the PSC. We Energies will own 80% of each project, while Wisconsin Public Service and Madison Gas and Electric will each own 10%.

The projects will cost $1.48 billion and are expected to come online in 2027 and 2028.

More: Wisconsin Public Radio

NERC Board Approves Committee Reorganization

At NERC’s final board meeting of 2025, Chair Suzanne Keenan reminded trustees that the ERO’s “mission is simple to say, but enormous to carry.”

“We don’t get the luxury of getting it wrong, and with the system changing fast and demand growing even faster, the stakes keep rising,” Keenan said. “I often think about what this will look like a decade from now, and I imagine a more settled landscape — still challenging, but steadier — where people look back and recognize how this industry rose to the moment, how we embraced change, pushed each other, trusted each other and stayed relentlessly focused on our mission.”

Keenan’s remarks set the tone for the brief but busy Dec. 5 meeting, in which trustees approved updates to the board’s committee structures and assignments, a proposal to retire a regional reliability standard, the ERO’s 2026 work plan priorities and its 2026/28 Reliability Standards Development Plan.

The committee reorganization included: the creation of a new board committee, the Engagement and Outreach Committee; and the disbanding of the Technology and Security Committee, which has overseen the Electricity Information Sharing and Analysis Center and the board’s information technology and information security programs. The new committee will take over E-ISAC oversight, while the Finance and Audit Committee will oversee the IT program. Oversight of information security will be assigned to the full board.

TSC Chair Jane Allen, who will transition to head the EOC, explained to the board the new committee’s goal will be “making sure that the things that NERC produces, the information, reports, standards, etc. [are] getting to the right people at the right time.” Keenan said the EOC’s responsibilities, in addition to E-ISAC oversight, will include “deepening NERC coordination with regional entities to reach decision-makers across North America.”

Keenan presented the board’s committee leaders for next year. Chairs for the committees will remain largely the same as 2025, except for Allen moving from TSC to EOC and Trustee Ken DeFontes taking over leadership of the Nominating Committee. Other committee chairs are:

    • Corporate Governance and Human Resources: Kristine Schmidt
    • Regulatory Oversight: Rob Manning
    • Finance and Audit: Colleen Sidford
    • Enterprise-wide Risk: Jim Piro

Schmidt brought to the board a proposal from the governance committee to set compensation for trustees designated as liaisons to or members of NERC’s standing committees, task forces or working groups to $7,500 or $10,000 per year, respectively. Liaisons are assigned to monitor and observe a standing committee or other group, while members are expected to fully participate in the group to which they are assigned.

NERC’s bylaws now state that the board’s liaisons to the Standards Committee and Reliability and Security Technical Committee — both roles filled now by Trustee Sue Kelly — be paid $7,500 per year. However, the bylaws make no provision for liaisons or members of other committees or groups. Schmidt said the rule change was intended as “a recognition of the effort” that such participation requires.

She added that the committee did not expect the board to assign trustees to committees, work groups or task forces on a regular basis, but “only under extreme circumstances when the board and the CEO feel that it’s necessary.” The board voted unanimously to approve the committee reorganization and the compensation proposal.

Standard Retirement and Development Plan Approved

Trustees also approved the retirement of regional reliability standard BAL-002-WECC-3 (Contingency reserve).

The standard, adopted by NERC’s board in 2019, “specifies the quantity and types of contingency reserves required to ensure reliability under normal and abnormal conditions,” the agenda said on Page 18. Under the standard, an entity must hold reserves based on 3% of load and 3% of generation, which NERC staff wrote is “more stringent than” NERC’s continent-wide standard BAL-002-3 (Disturbance control standard — contingency reserve for recovery from a balancing contingency event).

NERC Director of Standards Development Jamie Calderon told trustees that WECC has considered retiring the standard since 2020 and concluded earlier in 2025 that “the additional reserve requirements did not demonstrably improve reliability and instead created inefficiencies that hindered variable generation integration.”

NERC posted the proposal for a 45-day comment period that ended Oct. 30, with most comments supporting the retirement. Calderon said ERO staff recommended the board support the proposal as well, which trustees did without objection.

Finally, trustees accepted the Reliability Standards Development Plan for 2026/28. The RSDP includes time frames and resources for all standards development projects expected to begin during the relevant time period, and is subject to change based on standard authorization requests or FERC directives received prior to the plan’s submission to FERC.

Supreme Court Justices Seem Skeptical on Agency Independence

The Supreme Court appeared ready to overturn a precedent that has maintained the independence of regulatory agencies like FERC for the past 90 years.

Justices heard oral arguments in Trump v. Slaughter, a case that springs from President Donald Trump firing Federal Trade Commissioner Rebecca Slaughter earlier in 2025. Commissioners at the FTC, FERC and other agencies enjoy “for cause” firing protections under Humphrey’s Executor, which a recent amicus brief argued has ensured agency independence. (See Former FERC Commissioners Ask Supreme Court to Preserve Agency Independence.)

Multiple justices appointed by Republicans questioned Amit Agarwal, the special counsel for Protect Democracy who argued for Slaughter, on why Congress could not just expand multimember commissions to take over the work of EPA or the Commerce Department, thus insulating them from presidential oversight.

Some executive agencies, including the State Department and the Department of Defense, are pre-empted from that entirely under the Constitution because they are wielding the president’s “conclusive and preclusive constitutional authorities,” Agarwal said.

Chief Justice John Roberts asked whether Congress could reorganize the Department of Veterans Affairs, or the Department of Education, so they are run by a commission with officers that could be removed only for cause.

“Yeah, I think that it is probably within the realm of possibility for agencies, yes, Chief Justice Roberts,” Agarwal said. “And the constraint historically has been that these types of determinations have been made through a process of political accommodation between Congress and the president.”

Justice Elena Kagan argued that the bigger risk would not be Congress usurping executive authority with new bipartisan commissions, but that if the Trump administration wins, then the Education Department still would be authorized by Congress but without any employees.

“I think you’re absolutely right, Justice Kagan, that there are competing dangers here, and it makes a whole lot of sense to us to weigh the real-world dangers that we know are a virtual certainty that would result from adopting petitioners’ constitutional theory,” Agarwal said.

He then added that Congress has never tried to convert an executive agency, as Roberts and several other justices postulated it could. Justice Amy Coney Barrett said that does not prevent that from happening in the future.

In Humphrey’s Executor, the court recognized that such agencies exercise legislative and judicial powers while still engaging in some executive function, but that does not make it an executive agency, Justice Ketanji Brown Jackson said.

Many agencies have been involved in civil enforcement cases, and the Supreme Court has never found any of them were therefore ineligible to have principal officers covered by for-cause protection, Agarwal said.

“You are just saying that the way the law has been interpreted by the court here, the existence of Humphrey’s and Congress’ reliance on these kinds of multimember agencies for something like 90 years plus, that’s the background rule,” Jackson said. “And so now it’s up to the government and the solicitor general to come in to suggest that there’s a constitutional problem with that.”

The FTC Act is 111 years old, and Humphrey’s has been case law since 1935, Agarwal noted, and he argued that similar setups go back to the earliest days of the U.S.

Justice Brett Kavanaugh asked whether it would be appropriate to give FTC commissioners or others with protections under Humphrey’s Executor terms of up to 20 years. Agarwal argued that would be prevented by the Take Care Clause in Article II, Section 3 of the Constitution, as commissioners’ time in office would span multiple presidencies.

“We don’t dispute that the activities of these agencies are operating within the purview of the executive branch and they should be subject to constitutionally appropriate presidential supervision,” Agarwal said.

Most of the regulators at issue in the case allow the president to pick a chair from among Senate-approved members for any reason, and Kavanaugh asked if that was required. Agarwal said it was not constitutionally required because when Humphrey’s Executor was decided, the chair of the FTC was not removable, though the law changed 15 years later.

“I think putting those three together, your position would allow Congress to create independent agencies, maybe converting some of the existing executive agencies into independent agencies with no political balance requirement, with a long term, say, 10 or more years, and with the chairs not subject to removal as chair,” Kavanaugh said. “So, you can imagine a situation — and I just want to give you a chance to deal with the hard hypothetical — when both houses of Congress and [the] president are controlled by the same party [and they create] a lot of these independent agencies or extending some of the current independent agencies … so as to thwart future presidents of the opposite party.”

That would be constitutionally untenable because the president needs the authority to enact the law, Agarwal said. He cited Seila Law v. CFPB, in which the court found that the Consumer Financial Protection Bureau, which was run by one executive director, was not covered by Humphrey’s Executor, but the FTC, with its staggered seven-year terms and removeable chair, is on the right side of the line.

“If it is really true that these kinds of for-cause removal protections, which after all authorize the president to fire commissioners just for good cause, if they really pose this fundamental threat to the Republic, petitioners could take their argument across the street and Congress could solve the problem tomorrow,” Agarwal said. “They’re not willing to do that.”

The Federal Reserve Board of Governors benefits from the same protections as the FTC and FERC, but in a decision earlier in 2025 overruling the stay a lower court had placed on Trump’s firing of National Labor Review Board (NLRB) and Merit Systems Protection Board (MSPB) members, the Supreme Court indicated its own separate legislative history.

Kavanaugh asked Solicitor General D. John Sauer about whether the effort to bring other regulatory agencies under greater presidential control would undermine the central bank’s independence.

“We recognize and acknowledge what this court said in the [Trump v. Wilcox] stay opinion, which is that the Federal Reserve is a quasi-private, uniquely structured entity that follows a distinct historical tradition of the First and Second Banks of the United States,” Sauer said.

Any issues of removal restrictions from the Federal Reserve would raise their own unique distinct issues, he added.

Justice Kagan then asked, based on the arguments that all executive power is vested in the president, what would stop the courts from expanding the decision to cover even the civil service.

“Employees are wielding executive power all over the place, and yet we’ve had civil service laws that give them substantial protection from removal for over a century,” Kagan said. “How about those?”

Sauer said the case was not challenging the structure of the civil service, and the court has made clear in past decisions that its impacts are limited to the issues at hand.

“Logic has consequences,” Kagan said. “Once you use a particular kind of argument to justify one thing, you can’t turn your back on that kind of argument if it also justifies another thing in the exact same way. Putting a footnote in an opinion saying, ‘We don’t decide X, Y and Z because it’s not before us,’ doesn’t do much good if the entire logic of the opinion drives you there.”

D.C. Circuit Weighs in

Just days before the Supreme Court heard oral arguments in the Slaughter case, the D.C. Circuit of Appeals issued a decision in the case involving fired members of the NLRB and MSPB.

The court sided with Trump in the firings, but without overturning Humphrey’s Executor.

“Congress may not restrict the president’s ability to remove principal officers who wield substantial executive power,” the two-judge majority said. “As explained below, the NLRB and MSPB wield substantial powers that are both executive in nature and different from the powers that Humphrey’s Executor deemed to be merely quasi-legislative or quasi-judicial.”

The majority noted that after Humphrey’s Executor, other decisions had erased the distinction about “quasi-legislative” and “quasi-judicial,” while others found that only three kinds of constitutional power exist and only executive power can be delegated.

“These considerations suggest that very little remains of Humphrey’s Executor,” the circuit court said.

Judge Florence Pan filed a dissent to the decision, saying some agencies’ independence benefits the public and the multimember commissions at issue in Humphrey’s Executor have been around for 138 years.

“For at least 90 years, it has been settled law that Congress may impose statutory for-cause removal protections in the exercise of its authority to organize and structure the executive branch,” Pan wrote. “But today, my colleagues make us the first court to strike down the independence of a traditional multimember expert agency: They hold that the for-cause removal protections that safeguard the political independence of the National Labor Relations Board and the Merit Systems Protection Board are unconstitutional.”

PJM Operating Committee Briefs: Dec. 4, 2025

November Operating Metrics

PJM’s forecasting of hourly peak loads  continued to improve in November, with an error rate of just 1.17%, lead engineer Marcus Smith told the RTO’s Operating Committee on Dec. 4.

And while the 1.31% error rate for hourly forecasts was higher than October, it remained below the two-year average, Smith said.

He said forecasts held up on Nov. 11, when Veterans Day coincided with the lowest temperatures of the month, while Thanksgiving was the coldest observed since 2018. Holiday load forecasts have taken on pronounced importance since December 2022’s Winter Storm Elliott, when gas generators struggled to determine whether they should nominate for fuel packages spanning the long weekend. (See PJM Recounts Emergency Conditions, Actions in Elliott Report.)

Nov. 20 was the only day with a peak error rate exceeding the RTO’s 3% error benchmark, with cooler weather pushing the peak load to 3.15% higher than forecast.

There were three spin events, three shared reserve events, two geomagnetic disturbance warnings, 13 shortage cases and 14 post contingency local load relief warnings in the month.

Eight of the shortage cases were declared on the morning of Nov. 18, leading stakeholders to question whether solar ramping was a factor. PJM’s David Kimmel said there have been a higher number of shortage cases related to solar over the past few months, but staff still are investigating the drivers on that day.

One shortage case was issued on Nov. 16 and four on the following day, which were attributed to software issues.

A Nov. 11 spin event lasted 10 minutes and 17 seconds, meeting PJM’s threshold for including it in a three-event rotating average being tracked for determining whether the RTO should back down a 30% adder on the synchronized and primary reserve requirement implemented in May 2023.

The RTO assigned 2,051 MW of generation, of which 80% responded, and 673 MW of demand response, with a 91% response. If performance across three events longer than 10 minutes exceeds 75%, the adder will be reduced by 10%, with the possibility of it being further reduced if performance is higher than 85 or 95%. (See PJM OC Briefs: March 6, 2025.)

Monitor Presents Synchronized Reserve Performance Inquiry

The Independent Market Monitor updated the results of its ongoing inquiry into the contributors to low synchronized reserve performance, which has involved reaching out to resource owners whose units under- or overperformed their commitments during deployments exceeding 10 minutes.

The Monitor first presented its findings during the OC meeting Nov. 3. (See PJM Monitor Presents Spin Event Performance.)

Communications issues have become less of a factor since the first event the Monitor investigated on July 8, 2024; however, inadequate training and incorrect parameters continue to be issues, it said.

Incorrect parameters were the largest cause of shortfalls during an Oct. 17 spin event, which saw 2,336 MW assigned with a response rate of 81%. The second largest cause was modeling issues, with the remaining contributors having too few respondents to be reportable because of confidentiality rules.

An Oct. 28 event saw 2,015 MW assigned and 69% responding, with software and hardware issues being the main driver, followed by incorrect parameters.

The Monitor recommended that PJM revise its reserve performance metrics by including all assigned reserves and recognizing overperformance in the calculation. Doing so would increase performance during the Oct. 17 event to 100% and result in 81% performance on Oct. 28.

PJM Seeks Quick Fix on Data Communications

PJM presented a quick-fix solution to revise Manual 1: Control Center and Data Exchange Requirements seeking to add clarity around how the RTO and members share information.

Language was added to reflect NERC’s reliability standard CIP-012-2 (Cybersecurity – communications between control centers), which requires entities to have plans to “mitigate the risks posed by unauthorized disclosure, unauthorized modification and loss of availability of real-time assessment and real-time monitoring data in transit between applicable control centers.” It details the RTO’s PJMNet system for internal communications.

The section detailing the RTO’s Energy Management System (EMS) would be revised to require members submitting distributed network protocol links to provide data maps and definitions. The language includes a statement that PJM will not consume or process data not required for its own purposes.

“This policy additionally ensures fair and balanced benefits of PJM [supervisory control and data acquisition] and networking resources, and ensures that PJM does not prematurely surpass inherent data size limits of the EMS,” the manual language reads.

PJM MIC Tackles Issue Charges, Problem Statements

PJM presented a quick fix proposal Dec. 3 to address instances in which offline generators are committed as secondary reserves and granted lost opportunity cost (LOC) credits, despite governing document language stating resources not synchronized have zero LOC. The quick fix pathway allows for an issue charge to be brought concurrent with a proposed solution.

The issue charge focuses on instances in which a resource that is offline when it is dispatched as secondary reserves comes online before that commitment begins. According to the problem statement, real-time security constrained economic dispatch (RT SCED) commits resources 10 minutes before each interval, but settlement is focused on revenue quality meter data when the commitment begins. If the resource begins injecting energy before the interval begins, it would appear as being online and eligible for LOC credits by the settlement calculations.

The proposal would use resources’ output at the time they are committed by RT SCED to determine if they are offline and, if so, set the real-time secondary reserve opportunity cost at zero.

1st Read on Flexible Resource Definition Clarification Issue Charge

PJM presented a first read on a problem statement and issue charge to reconsider how a resource is defined as flexible and eligible for LOC credits when committed in the day-ahead energy market on an offer with flexible parameters, but could be dispatched on schedules that are not flexible in real time. Under such circumstances, intermediate term (IT) SCED may not be able to determine whether the resource is economic and dispatch it.

The problem statement gave an example of a resource with a flexible cost-based schedule and an inflexible price-based schedule, which is committed on the former in the day-ahead market due to it failing the three pivotal supplier test when a transmission constraint is modeled. If that constraint does not materialize, IT SCED would revert to the price-based offer but be unable to evaluate whether it is economic due to the difference in the parameter flexibility. The resource would not be committed and would receive LOC credits for the duration of its day-ahead commitment on the cost-based offer schedule.

“Opportunities exist to consider whether a resource should be considered flexible for commitment and lost opportunity cost purposes if there are differences in startup time, notification time and min run time parameters amongst the available schedules,” the problem statement reads.

PJM’s Susan Kenney said the issue charge would explore whether the parameters in each of a resource’s offers should be reviewed before it is considered eligible for LOC credits.

Stakeholders argued there may be a deeper issue with the dispatching software if economic resources able to operate are not being dispatched.

PJM’s Brian Chmielewski said the issue is that regardless of whether a unit committed on a flexible schedule in the day-ahead run is economic, real-time dispatching is limited to evaluating all offers based on those flexible parameters.

The issue charge includes education on the definition of flexible resources, how they are committed and when a unit is eligible for LOC credits. It envisions changes to the RTO’s governing documents and manuals addressing LOC eligibility for flexible resources, with work expected to take around three months starting in January 2026. Changes to how IT SCED selects schedules would be out of scope.

Fuel Cost Policy Issue Charge

PJM and the Independent Market Monitor brought an issue charge seeking to address the potential for market sellers to inflate cost-based offers by acquiring fuel cost estimates from an affiliated supplier.

“There may be inherent incentives for a fuel supplier to provide a fuel cost estimate to an affiliated market seller or designated agent of such market seller that may not be reflective of the expected fuel cost or the market price. Such an outcome could be used by market sellers that have market power (e.g., fail the three pivotal supplier test) to potentially manipulate the market by obtaining a fuel cost estimate from an affiliated fuel supplier that may not reflect market pricing of fuel costs. Such an approach would allow market sellers to set energy prices at an uncompetitive level,” the problem statement reads.

The issue charge scope is limited to how fuel cost policies reflect affiliated suppliers of fuel versus independent third parties, while broader changes to the policies would be out of scope.

REAL Team Endorses DR Policy, CONE Value

DENVER — The SPP leadership team responsible for strengthening the grid operator’s resource adequacy construct and recommending policy directions closed out 2025 by endorsing two protocol changes related to demand response and the cost of new entry.

Meeting Dec. 3 during Denver’s first snowfall of the season, the Resource Energy and Adequacy Leadership (REAL) Team approved combined policies for demand response and load-responsible entity peak demand assessments and the value of the cost of new energy for 2026, representing the cost to build a new power plant.

The CONE value, increased to $139.85/kW-year for summer 2026, passed unanimously. However, the REAL Team split 7-5 over the DR and peak demand assessments (RR703), emblematic of the difficulty SPP has had in developing a demand response policy since 2017.

“Everyone knows that SPP has been in increasing complex and challenging issues all the time, and here we are again,” REAL Chair Kristie Fiegen, with South Dakota’s Public Utilities Commission, said after the vote. “The stakeholders have worked very, very hard on this. We have listened to a lot of comments the last six months, and we’ve made a lot of changes. Is it perfect? No.

“So, it may not be perfect today, but we can always come back to it, because we will continue to monitor and adjust this in the future.”

“We’re at a point where staff has considered input from a bunch of different stakeholders … It’s gotten us to a point where I think at least staff is comfortable and [can] support the policy, but it’s not ever going to be ideal,” said Natasha Henderson, SPP’s senior director of grid asset utilization. “I think the policy that we have before us does an adequate job of balancing that as we walk forward. We are going to learn and check and adjust.”

Henderson said the policy has reached the point where “hopefully, people can agree that it’s just and reasonable” and that it balances the affordability and reliability equation at the forefront of the utility industry.

SPP says demand response is “increasingly critical” as it looks at a future with rapid load growth, evolving resource mixes and tighter energy conditions. DR supports reliability, stabilizes prices during uncertainty and helps the region adapt to changing system dynamics, it said.

Staff said a structured DR policy provides entities with multiple participation pathways and market, reliability and potential load-modifying products. It will also help defer the cost of new generation and supporting resource adequacy compliance.

The intent is to increase the visibility and ability to deploy demand response by creating a participation model and accreditation framework for non-price-sensitive DR. SPP seeks to incent LREs to manage peak loads by qualifying non-registered or load-modifying demand response capable of performing when their peak loads exceed their qualified resources.

The assessment will require LREs to use qualified resources to meet demand when accounting for the risk considered in the loss-of-load expectation study that sets the planning reserve margin requirements. That will mean an accurate 50-50 forecast and not one that incorporates all risks.

The peak demand assessment (PDA) is a CONE-based evaluation performed after a weather season based on the variation of actual load from the entity’s load forecast.

The measure was opposed by Evergy’s Denise Buffington, Oklahoma Corporation Commission staffer Jason Chaplin, the Advanced Power Alliance’s Steve Gaw, Oklahoma Municipal Power Authority’s Dave Osburn and American Electric Power’s Richard Ross.

Ross proposed what he called a post-season review to identify the LREs with the largest underforecast amount, requiring them to explain their error in a report that would be delivered to the board’s Oversight Committee. He referred to the review as casting sunshine on any chronic forecasting problems and force members to “sharpen their pencils.”

“I think ours is pretty sharp as it is, but we can do more,” Ross said. “Some folks make fun of my cute little phrases, but the framework would be much like SPP is going to do already.”

“I can’t help but point out the irony of Richard’s ‘sunny day’ proposal when it’s snowing,” Henderson said, gesturing to the falling snowflakes outside.

She reminded the REAL Team that SPP’s tariff requires that a post-season analysis be conducted and a report published. Henderson said the report reviews every LRE and is then discussed by the Supply Adequacy Working Group.

Carrie Bivens, vice president of SPP’s Market Monitoring Unit, said the Monitor still had some outstanding issues with the proposed changes, despite its engagement with RTO staff. She called for clarity around dual participation to “clearly prohibit” loads that are already in a retail program from participating in DR but saved the bulk of her comments for the LREs’ peak demand assessment.

“This is a significant one for us,” Bivens said.

She said the MMU supports the policy’s key objective of efficiently deploying load-modifying resources to manage peak loads and could support a PDA to accomplish this if it assesses deficiencies based on actual load but does not support the current framework.

“If we continue down the path … we think that the deficiencies need to be based on actual load, and that would mean no error tolerance and no weather normalization,” she said. “We do think that this framework, the way it is proposed, actually weakens the RA incentive structure. We just think this policy inappropriately socializes risk to the members.”

In response, Henderson said SPP has already opened three DR-related strategic initiative requests (SIRs 812, 814 and 816) to tackle the MMU’s concerns. The grid operator uses SIRs as part of its strategic road map to meet its long-term goals.

CONE Value Changed

The REAL Team endorsed the CONE’s value — setting it at $139.85/kW-year, up from the current $85.61/kW-year — but did not vote on any changes to the calculation’s process.

SPP bifurcated the proposed tariff change (RR729) following feedback from the REAL Team, the Supply Adequacy Working Group and other stakeholders. Staff said a new revision request will be introduced to address broader process changes, allowing additional time for stakeholder feedback and further development of the inputs and assumptions used to recalculate the CONE’s value.

The grid operator sets its CONE value annually by Nov. 1. Resource adequacy staff adjust the value for inflation and update tax rates and interest rates. It uses U.S. Energy Information Administration data for a generic generator in a region without any special considerations for altering cost as part of the calculation.

The REAL Team unanimously endorsed the measure, with Buffington abstaining.

The Board and Directors and Regional State Committee must both approve the CONE value change.

Fall Alert Hours Drop in 2025

SPP staff told the REAL Team that operations alerts and advisories, which have increased over the past three fall seasons, resulted in only 45 alert hours this year. In October 2024, the grid operator issued a conservative operations advisory and went through 194 alert hours.

Staff said mild September weather and fewer resource outages in late October led to the decrease.

More than 26 GW of outages were recorded in mid-October, consistent with outage trends during the shoulder months in the last three years. By early November, outages were tracking as much as 4 GW below the five-year norm.

Still, the grid operator issued its first resource advisory of the winter Nov. 29 for the entire balancing authority because of expected high peak loads, wind forecast uncertainty, severe cold weather and potential for above-normal generation outages.

SPP treats resource advisories to be normal operating conditions, two steps away from a Level 1 energy emergency alert. Resource advisories are issued to raise awareness in the market and don’t require conservation measures.

The RTO issued seven resource advisories and three conservative operations advisories — the last step before an EEA — during the summer. Staff issued 11 resource advisories during the summer of 2024 and three calls for conservative operations.

New Leadership to Meet

The REAL Team meeting was the last for Fiegen, who has chaired the group since its inception in 2023.

Chuck Hutchison, a member of the Nebraska Power Review Board, will succeed Fiegen as chair in 2026. He said he and SPP Board Chair Ray Hepper and SPP’s Henderson and Casey Cathey will meet to discuss the REAL Team’s work plan for next year.